Process for removing sulfur compounds from hydrocarbon streams

ABSTRACT

A process is presented for the removal of contaminants like sulfur compounds from hydrocarbons. The sulfur compounds are removed from hydrocarbons that may be a feed to cracking units. A feed stream is treated with a clinoptilolite or a barium exchanged zeolite adsorbent to effectively remove carbon disulfides from the feed hydrocarbon. The adsorbent may be regenerated by a hydrogen stream, a hydrocarbon stream or a mixture thereof.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority from Provisional Application No.62/219,381 filed Sep. 16, 2015, the contents of which are herebyincorporated by reference.

BACKGROUND

The present subject matter relates generally to methods for the removalof sulfur compounds from hydrocarbon streams. More specifically, thepresent subject matter relates to the methods for the removal of carbondisulfide from petrochemical grade naphtha fed to an ethylene plant, byuse of selective adsorbents.

Hydrocarbons used by industry should be produced to be as pure asnecessary without the presence of contaminants over specified limits.Conventionally, many of the organic sulfur compounds fed to an ethylenecracker decompose to form hydrogen sulfide. While some thermaldecomposition of carbon disulfide occurs, the remaining carbon disulfidein the cracker remains unconverted. The petrochemical grade naphtha fedto the cracking unit has to meet the product specification limits ofcarbon disulfide for any further use. Therefore, there is a need toremove carbon disulfide contaminants from the petrochemical naphtha tomeet the product specifications for commercial use.

The presence of carbon disulfide in the cracked stream also affectsdownstream processing. Carbon disulfide can poison the selectivehydrogenation catalysts that are generally used to remove acetylenes anddienes in olefin plants. The noble metal catalysts are very sensitive tosulfur and degrade in the presence of sulfur contaminants. Carbondisulfide also contaminates C4 and C5 olefins and dienes production inpolymer plants and can be corrosive when it undergoes transformation toH2S. Therefore, there is a need for a process for removal of carbondisulfide from the hydrocarbon streams.

In one prior art process, the cracked gas is directed to acid gasscrubber for caustic wash. The acidic contaminants and hydrogen sulfideare readily removed by caustic wash. However, carbon disulfidecontaminants present in the gas are not effectively removed by causticwash.

Carbon disulfide (CS2) is a contaminant found in refinery and condensatehydrocarbon streams and elutes with the light naphtha fraction. Theconcentration of CS2 in the naphtha fraction varies considerably,depending upon the source of the hydrocarbon stream. Typically, alongwith CS2 in these hydrocarbon streams are found other sulfur speciessulfur as mercaptans, sulfides, and disulfides which usually are presentin higher concentrations. When such CS2 containing naphtha streams areexported as feedstock to steam crackers (primarily for ethyleneproduction), it can result in the production of off-spec C5 derivatives.This then affects the downstream production quality of, among otherthings, synthetic rubber. Normally, CS2 is present at very low levels(<10 ppm). Along with CS2 in these hydrocarbon streams are other sulfurspecies like mercaptans, sulfides, and disulfides which usually are inhigher concentrations. Many hydrocarbon streams are treated withcatalysts to change their form, such as, isomerizing, reforming,hydrocracking, etc. Sulfur and oxygen containing organic compoundsdeactivate these catalysts. Heretofore, the oxygenates (i.e. methanol,dimethyl ether, acetone, acetaldehyde, etc.) can be removed byadsorption easily with molecular sieves. The sulfur species mercaptans,sulfides, and substituted disulfides (dimethyldisulfide,methylethyldisulfide, diethyldisulfide etc.)) are removed by adsorption.However, CS2 is too light to normally be removed with conventionalsulfur removing commercial adsorbents such as 13X, 4A, and 5A. Insteadof removing the CS2, usually the sulfur specification can be met byremoving all of the other sulfur species present, even though the CS2passes through.

With the advent of lower sulfur specifications for fuels, even thepresence of relatively low levels of CS2cannot be ignored. Therefore,there is a need for an adsorbent that can effectively remove CS2 that ispresent at low levels (10-20 ppm). Normally, hydrocarbons adsorb morestrongly than CS2 in conventional zeolites (4A, 5A, 13X) so an adsorbentis needed whose pore size is appropriate to allow CS2 to be adsorbedwhile excluding the hydrocarbons. In addition, carbon disulfide levelscan also cause catalyst poisoning in other polymer plant feedstockproduction. As a consequence, petrochemical naphtha (PCN) users havemoved to limit feed CS2 to <1-2 ppm.

SUMMARY

An embodiment of the subject matter is a process for removing sulfurcompounds from hydrocarbon streams comprising contacting a hydrocarbonstream with a clinoptilolite adsorbent to remove carbon disulfide toproduce an effluent stream. Sodium clinoptilolite and bariumclinoptilolite were found to be very effective in removal of carbondisulfide.

A second embodiment of the subject matter is a process for removingsulfur compounds from hydrocarbon streams comprising an adsorbent bed incommunication with a hydrocarbon stream to remove at least carbondisulfide from the product stream. The adsorbents comprise sodiumclinoptilolite, barium clinoptilolite or mixtures thereof. Thehydrocarbon stream may be sent to a hydrotreating unit which serves toreduce the sulfur, nitrogen, oxygenates and aromatic content of thehydrocarbon stream. A portion of the resulting treated hydrocarbonstream may be used to regenerate the adsorbent bed. This regenerantstream comprises mostly saturated hydrocarbons which are suitable forregeneration at elevated temperatures to avoid coking from condensationand/or reaction of unsaturates on the adsorbent. The regenerant streammay be recycled to the hydrotreater in the event that there areunsaturated hydrocarbons that are desorbed from the adsorbent during theregeneration process. The regenerant stream may also be sent to thehydrotreater for the CS2 to be treated in the hydrotreater. In anintegration of the naphtha hydrotreater with the adsorbent bed, thestabilized naphtha hydrotreater bottom or naphtha splitter overheadstream can be used as a regeneration medium and the regenerationeffluent can be directed to the hydrotreater feed. The advantage ofusing the stabilized naphtha hydrotreater effluent is to use the hotstream in order to minimize the energy needed for regeneration heatingand the spent hot regeneration effluent can be directed to thecombination with the hydrotreater feed upstream of the charge heater orreduce the overall energy requirement of the process. In otherembodiments of the invention, the regeneration stream may be a hydrogenstream that after passing through the adsorbent bed may be sent to thehydrotreater, a hydrocracker or to another hydrogen consuming process.

These and other features, aspects, and advantages of the present subjectmatter will become better understood upon consideration of the followingdetailed description, drawings and appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a flow scheme with the regeneration stream that is a slipstream of the treated product stream from the adsorbent bed.

FIG. 2 shows two options for sending a regeneration stream to theadsorbent bed that has been treated in a hydrotreater.

FIG. 3 shows an option to use part or all of a make-up hydrogen streamto an existing hydrotreater as the regeneration medium for the adsorbentbed.

DETAILED DESCRIPTION

Naphtha from the crude distillation section is fed to ethylene crackingunits for further processing. The crude naphtha may be contaminated withcarbon disulfide. Carbon disulfide inhibits chemical reactions bydeactivating the catalysts used for selective hydrogenation. Therefore,carbon disulfide is an undesirable contaminant that needs to be removedfrom the crude naphtha to meet the product specification of naphtha forcommercial use.

Typically, contaminants are removed from the cracked hydrocarbons bycaustic wash. The contaminants such as hydrogen sulfide and other acidiccontaminants are removed readily from the cracked hydrocarbons bycaustic wash. However, carbon disulfide is not effectively removed andis subsequently carried with the hydrocarbon to downstream fractionationand treating sections. This affects downstream processing and leads toundesirable reactions like fouling.

The present invention provides a new method to remove carbon disulfidefrom feed to ethylene cracking units by using a clinoptilolite adsorbentor a barium ion-exchanged zeolite to remove the carbon disulfide fromthe cracker feed. The benefit of this method is that the removal ofcarbon disulfide enables economical processing of the feedstock incracking units. In addition, in an embodiment of the invention, theadsorbent bed may be regenerated by use of a hydrotreated hydrocarbonstream. This regeneration stream may first pass through the adsorbentbed to remove carbon disulfide as well as unsaturated hydrocarbons andthen be sent back through the hydrotreater.

In the practice of the invention, an adsorbent column containsclinoptilolite adsorbent. The clinoptilolite adsorbent has exchangeablecations selected from ions of Group 1A, Group 2A, Group 3A, Group 3B,the lanthanide series and mixtures of these. The clinoptilolite isselected from natural clinoptilolite, synthetic clinoptilolite,sodium-exchanged clinoptilolite, potassium-exchanged clinoptilolite,lithium-exchanged clinoptilolite, calcium-exchanged clinoptilolite,magnesium-exchanged clinoptilolite, barium-exchanged clinoptilolite, andmixtures thereof. Preferably, the clinoptilolite is sodium-exchangedclinoptilolite or barium-exchanged clinoptilolite. In addition, it hasbeen found that the adsorbent column may contain a natural or asynthetic zeolite having a chabazite or an erionite structure. Mixturesof chabazite, erionite and clinoptilolite adsorbents that are exchangedwith sodium, potassium, lithium, calcium, magnesium or barium andmixtures thereof may be used. Preferably, the adsorbent is a chabazite,an erionite, a clinoptilolite or mixtures thereof that is exchanged withbarium.

Clinoptilolites are a natural occurring zeolite comprising a microporousarrangement of silica and alumina tetrahedra. While it has beenpreviously used for removal of some other impurities, it has not beenpreviously known to be effective for the removal of carbon disulfide innaphtha boiling range feedstocks. An additional adsorbent layer orcolumn may be used to remove other types of impurities.

A chabazite or an erionite zeolite has also been found effective in thepresent invention. A barium exchanged zeolite that has been foundeffective is a mineral zeolite that comprises approximately 50 wt %chabazite, 40 wt % erionite, 5 wt % clinoptilolite and the remainderamorphous material. This material is a barium exchanged version ofadsorbent that may be 1/16″ or ⅛″ pellets or other configuration and hasa general chemical formula of M_(x)[(AlO₂)_(x)(SiO₂)_(y)].z H20 where[M=Na,K,Ca,Mg]. This material is barium exchanged.

The term “adsorption” as used herein encompasses the use of a solidsupport to remove atoms, ions, and molecules from a gas or liquid. Theadsorption may be by “physisorption” in which the adsorption involvessurface attractions or “chemisorptions” where there are actual chemicalchanges in the contaminant that is being removed. Either temperatureswing adsorption or displacement process may be employed in regenerationof the adsorption process. A combination of the processes may also beused. The adsorbents may be any porous material known to have anapplication as an adsorbent including carbon materials such as activatedcarbon clays, molecular sieves including zeolites and metal organicframeworks (MOFs), metal oxides including silica gel and alumina thatare promoted or activated, as well as other porous materials that can beused to remove or separate the contaminants.

There is also provided a process to reduce the CS2 content ofpetrochemical grade naphtha using a size selective adsorbent such as abarium, or sodium clinoptilolite. This is a cost effective option toallow refiners to meet the CS2 specification of petrochemical gradenaphtha. Accomplishing the CS2 separation in this way overcomes theobstacles of interference and co-adsorption of not only the naphthaboiling range hydrocarbons, since these are excluded from the adsorbentpores, but additionally obviates the need to unnecessarily have toremove the other organic sulfur compounds, such as mercaptans or heavyoxygenates such as MTBE and TAME since they may compete with CS2adsorption. This allows for design of adsorbent beds that are muchsmaller (more economical) than traditional adsorbents. While manyadsorbents have been commercially used, and demonstrated to be suitablefor carbon disulfide removal, the presence of other organic sulfurspecies such as mercaptans and sulfides in the stream along withhydrocarbon coadsorption will severely limit the adsorbent's CS2capacity. Therefore it has not economically practical to remove CS2 fromnaphtha by using adsorbents.

The currently viable method to remove CS2 from naphtha is via thewell-known hydrotreating option. In many cases the existinghydrotreating assets do not have sufficient available capacity toprocess the petrochemical naphtha stream and building a grass rootshydrotreater for this purpose is a very expensive (capital expense)option that cannot be justified. In addition, the hydrotreating optionfor CS2 removal will also result in much more hydrogen consumption thanthat required for CS2 removal alone, since there will be additionalsulfur, oxygenate and nitrogen compounds that will be converted, inaddition to aromatics saturation.

In one embodiment of reducing the proposed TSA (thermal swingadsorption) mode of operation to commercial practice is to use a slipstream of the product for regeneration of the beds. The TSA mode ofoperating adsorbents in order to continuously produce a treated streamis a well-known and commercially practiced technology. However, findinga suitable clean regeneration stream to regenerate the beds can bechallenging and is one of the considerations that can make theadsorption option for purification economically disadvantageous.Integrating the regeneration stream into a refinery is not trivial,since this can made the process viable or uneconomical.

The regeneration effluent now contains CS2 and needs to be suitablydisposed. One of the options for doing so is to send this much smallerstream typically 10-20% of the total feed processed to an existingnaphtha hydrotreater, which should be able to accommodate a much smalleradditional stream, as opposed to the complete petrochemical naphthastream.

In another embodiment of process integration of the TSA unit, thestabilized naphtha hydrotreater bottom, or the naphtha splitter overheadstream can be used as a regeneration medium and the regenerationeffluent can be directed to the hydrotreater feed. The advantage usingthe stabilized naphtha hydrotreater effluent is to use the ‘hot’ streamin order to minimize the energy required for regeneration heating andthe spent hot regeneration effluent can be directed to the combine withthe hydrotreater feed upstream of the charge heater or reduce theoverall energy requirement of the process.

The adsorbent may be operated as a non-regenerative guard bed to polishthe residual carbon disulfide present in the naphtha stream after aseparate treatment to remove a portion. The petrochemical naphtha isremoved from the bottom of the adsorbent column and has less than 1wpprn carbon disulfide. The petrochemical naphtha may then be directlysent for cracking and further use.

The removal of carbon disulfide from naphtha by use of adsorption in apacked bed thermally regenerated system with the use of clinoptiloliteadsorbents provides an effective removal of carbon disulfide of about90% and preferably about 99% of the carbon disulfide from the crudenaphtha. The crude naphtha used as feed for further cracking and othercommercial uses is free of carbon disulfide and as a result avoidsconsequent undesirable downstream reactions like fouling or deactivationof catalysts.

The barium clinoptilolite shows an increased capacity for CS2 at thehigher concentration. This result is counter intuitive since the bariumcation is larger (atomic volume=38.21 cm3/mol) than the sodium cation(atomic volume=23.70 cm3/mol). Even taking into account the fact thatbarium is a divalent cation and therefore would only require ½ as manycations to balance the zeolite surface charge as sodium cations, the CS2capacity should only be increased by the ratio of the atomic volumes((23.70/(38.21/2))=1.24. Instead the CS2 capacity at the high end isalmost twice the amount (3.001/1.553=1.93). Apparently, the bariumcation has the ability to modify the pore shape to increase the volumeavailable for molecules like CS2. This is a surprising result as shownin the results in the Table.

In Table 1, the results for several different adsorbents in removing 400ppm carbon disulfide from n-heptane are shown. The barium clinoptiloliteand the sodium clinoptilolite performed much better in removing carbondisulfide than any of the other adsorbents.

TABLE 1 Feed Load- Liquid Sample Liq/Sol Conc. Conc ing Sample Test # Wt(g) Wt (g) g/g ppm Ppm wt % 3A zeolite 2A 50.00 0.26 1.9E+02 452 4280.462 (K 2B 20.65 0.52 39.7 452 414 0.151 exchanged) 2C 10.09 1.04 9.7452 410 0.041 Ba Clino 3A 50.00 0.26 1.9E+02 452 296 3.001 3B 20.01 0.5337.8 452 36 1.571 3C 10.03 1.00 10.0 452 7 0.041 Na Clino 4A 51.12 0.271.9E+02 452 370 1.553 4B 20.16 0.51 39.5 452 88 1.439 4C 10.00 1.00 10.0452 17 0.435 Open pore 5B 20.00 0.51 39.2 452 407 0.176 3A 5C 10.03 1.0010.0 452 384 0.068

In Table 2 is shown the results with the barium exchanged adsorbent thatis a mixture of about 50 wt % chabazite, 40 wt % erionite and 5 wt %clinoptilolite (remainder amorphous material) with a first run followedby two different runs using an adsorbent bed that has been regenerated.The feed that was treated with this adsorbent contained 200 ppm carbondisulfide, 200 ppm C3H7SH in a mixture of n-hexane, n-heptane,iso-octane and toluene.

TABLE 2 C3H7SH Feed CS2 in Total in feed Total Conc Feed as CS2 as SC3H7SH Liquid Sample Liq./Sol. (XRF) S (GC) (feed) (GC) in feed SampleRun # Test # wt. (g) wt. (g) g/g ppm ppm ppm ppm ppm Ba zeolite 1 A15.73 0.11 1.5E+02 265 172 204 92 219 B 15.41 0.16 9.9E+01 265 172 20492 219 C 15.53 0.20 7.6E+01 265 172 204. 92 219 D 15.12 0.30 5.0E+01 265172 204 92 219 E 15.69 0.76 2.1E+01 265 172 204 92 219 F 15.46 1.011.5E+01 265 172 204 92 219 G 15.24 1.51 1.0E+01 265 172 204 92 219 Baexchanged 1 A1 15.42 0.11 1.5E+02 265 170 202 95 226 zeolite Regen #1 B115.40 0.16 9.7E+01 265 170 202 95 226 C1 15.62 0.21 7.6E+01 265 170 20295 226 D1 15.88 0.30 5.3E+01 265 170 202 95 226 E1 15.50 0.75 2.1E+01265 170 202 95 226 F1 15.84 1.00 1.6E+01 265 170 202 95 226 G1 15.631.48 1.1E+01 265 170 202 95 226 Ba exchanged 1 A2 15.61 0.11 1.5E+02 265170 202 95 226 zeolite Regen #2 B2 15.11 0.16 9.5E+01 265 170 202 95 226C2 15.65 0.21 7.6E+01 265 170 202 95 226 D2 15.62 0.30 5.2E+01 265 170202 95 226 E2 15.33 0.75 2.0E+01 265 170 202 95 226 F2 15.16 1.001.5E+01 265 170 202 95 226 G2 15.22 1.48 1.0E+01 265 170 202 95 226Adsorption Unknown + Total heavies S in CS2 C3H7SH in feed as Sample asS Total as S Total S (GC) (XRF) (GC) CS2 (GC) C3H7SH Sample Run # Test #ppm ppm ppm ppm ppm ppm Ba zeolite 1 A 0 155 88 104 47 111 B 0 130 65 7835 83 C 0 108 52 61 27 64 D 0 77 32 38 12 28 E 0 45 13 15 3 6 F 0 48 7 80 0 G 0 38 13 15 3 6 Ba exchanged 1 A1 0 184 106 125 59 140 zeoliteRegen #1 B1 0 159 87 104 48 114 C1 0 126 62 74 36 86 D1 0 89 33 39 19 45E1 0 49 12 14 5 12 F1 0 43 11 13 6 13 G1 0 38 12 14 5 12 Ba exchanged 1A2 0 185 109 129 57 135 zeolite Regen #2 B2 0 167 88 105 42 100 C2 0 14573 86 40 95 D2 0 98 35 41 20 48 E2 0 52 12 14 2 5 F2 0 58 19 22 7 16 G20 0 0 0 Other Sulfur Species Loading Other S CS2 Total C3H7SH TotalC6H1452 Total species Total S loading CS2 loading C3H7SH as S (GC)C6H14S2 (GC) Loading as S Loading as S loading Sample Run # Test # ppmppm ppm wt % wt % wt % wt % wt % Ba zeolite 1 A 20 47 0 1.615 1.2371.469 0.670 1.591 B 29 68 1 −1.282 1.053 1.250 0.567 1.346 C 29 68 0−0.821 0.917 1.089 0.497 1.181 D 33 77 1 −0.386 0.703 0.835 0.404 0.958E 29 68 0 −0.093 0.330 0.392 0.187 0.443 F 40 94 1 −0.074 0.253 0.3010.142 0.337 G 22 52 0 −0.038 0.161 0.191 0.091 0.216 Ba exchanged 1 A119 44 1 −2.695 0.945 1.122 0.526 1.249 zeolite Regen #1 B1 23 55 1−1.544 0.804 0.955 0.458 1.087 C1 27 64 0 −0.959 0.821 0.975 0.446 1.059D1 36 84 2 −0.469 0.725 0.860 0.400 0.950 E1 31 73 1 −0.101 0.325 0.3860.185 0.440 F1 26 61 0 −0.068 0.253 0.300 0.142 0.337 G1 21 48 0 −0.0400.167 0.198 0.095 0.226 Ba exchanged 1 A2 18 42 1 −2.724 0.898 1.0660.559 1.329 zeolite Regen #2 B2 29 67 8 −1.584 0.778 0.924 0.503 1.194C2 32 74 1 −1.095 0.735 0.873 0.417 0.990 D2 42 97 2 −0.507 0.700 0.8320.387 0.919 E2 38 88 1 −0.106 0.323 0.383 0.189 0.449 F2 32 75 0 −0.0880.229 0.272 0.134 0.317 G2 0 0 0.000 0.174 0.207 0.097 0.231

FIG. 1 shows a flow scheme in which the regeneration stream is a slipstream of the product stream from the temperature swing adsorption bedthat removes the CS2 impurities. A stream 1 that is a crude orcondensate stream containing a full range of hydrocarbons is sent to acrude column 2 to produce a straight run naphtha stream 4. The crudecolumn 2 sends alight stream 5 and a heavy stream 7 that are separatelyprocessed. A portion of straight run naphtha stream 4 is shown as stream6 that is sent to other users that do not require the CS₂ impurities tohe removed and the rest of straight run naphtha stream 4 is sent to atemperature swing adsorption bed 10 that contains a clinoptiloliteadsorbent. This bed operates at temperatures between about 15.5 to 65.5°C. (60-150° F.). A purified product stream 12 exits the bottom oftemperature swing adsorption bed 10 with about 80-90% of this treatedproduct stream being sent to an ethylene cracker. About 10-20% of thisproduct stream is sent in slip stream 16 to a temperature swingadsorption bed 20 that needs regeneration that takes place attemperatures from about 148.9 to 287.8° C. (300 to 550° F.). A stream 22exits the top of temperature swing adsorption bed 20 to be sent to anaphtha hydrotreater (not shown). Since this stream 22 is a smallfraction of the product stream, the naphtha hydrotreater has thecapacity to treat the impurities in this stream.

FIG. 2 shows two additional embodiments of the invention for treating astraight run naphtha stream with the adsorbents used in the presentinvention and regenerating the adsorbent bed. A straight run naphthafeed 101 is sent to a temperature swing adsorption bed 102 that containsthe adsorbents used in the present invention and a treated productstream 104 is then sent to an ethylene plant to be used as feed stream.The remainder of FIG. 2 describes the flow scheme related to thedesorption portion of the TSA process. A regeneration stream 106 that isabout 148.9 to 287.8° C. (300 to 550° F.) is sent to TSA bed 110 that isbeing regenerated. A stream 112 that contains the impurities removedfrom TSA bed 110 is then sent to a hydrotreater 120. Stream 112 is firstadded to a make-up hydrogen stream 114 that is heated by heat exchanger116 and then the heated stream 118 is sent to hydrotreater 120. Theeffluent 122 then is cooled at heat exchanger 124 and sent to separator130 to remove light ends in stream 132 including hydrogen to be recycledto hydrotreater 112. A bottoms naphtha stream 134 is heated in a bottomsheat exchanger 136 and sent to naphtha stabilizer 150. A light endsstream 152 that includes H2S and H2O is removed and a bottoms stream 154is removed and passes through bottoms heat exchanger 136. A portion ofthe heated bottoms stream may be sent in stream 156 to regenerate TSAbed 110 and the remainder of the heated bottoms stream may be sent instream 158 to naphtha splitter 160 which produces a light naphtha stream162 and a heavy naphtha stream 164. A portion 162 of light naphthastream may be sent to regenerate TSA bed 110 with the remainder of thelight naphtha stream in stream 166. In the process, the regenerationstream is first heated to the desired temperature range between about148.9 to 287.8° C. (300 to 550° F.) and preferably 933-204.4° C.(200-400° F.).

FIG. 3 shows the use of the make-up hydrogen stream to a hydrotreaterbeing used as the regeneration medium for the adsorbent beds in thepresent invention. A straight run naphtha feed 201 is sent to atemperature swing adsorption bed 202 that contains the adsorbents usedin the present invention and a treated product stream 204 is then sentto an ethylene plant to be used as feed stream. The remainder of FIG. 3describes the flow scheme related to the desorption portion of this TSAprocess. A regeneration stream 206 comprising hydrogen is heated at heatexchanger 208 with the resulted heated hydrogen stream 209 going throughTSA bed 210 that is being regenerated. A hydrogen stream 214 then exitsTSA bed 210 and together with naphtha stream 240 is heated by heatexchanger 216 and enters hydrotreater 220. An effluent 222 is thencooled at heat exchanger 224 and cooled stream 226 is sent to separator228 to remove light ends in stream 226. A recycle stream 138 containinghydrogen is returned to hydrotreater 220 while a bottoms naphtha stream242 is sent through bottoms heat exchanger 244 to separate a heavynaphtha stream 250 with the remainder of the naphtha stream being sentto naphtha splitter 252 with light ends 254 exiting the top of naphthasplitter 252 and the remainder exiting the bottom of naphtha splitter252 to be combined with heavy naphtha stream 250. In other embodimentsof the invention, the hydrogen may be sent to a hydrocracker or anotherhydrogen consumption process.

While the subject matter has been described with what are presentlyconsidered the preferred embodiments, it is to be understood that thesubject matter is not limited to the disclosed embodiments, but it isintended to cover various modifications and equivalent arrangementsincluded within the scope of the appended claims.

Specific Embodiments

While the following is described in conjunction with specificembodiments, it will be understood that this description is intended toillustrate and not limit the scope of the preceding description and theappended claims.

A first embodiment of the invention is a process for removing CS2 fromhydrocarbon streams comprising contacting a hydrocarbon stream with aclinoptilolite adsorbent or a barium exchanged zeolite adsorbent toproduce a hydrocarbon stream having a reduced CS2 content. An embodimentof the invention is one, any or all of prior embodiments in thisparagraph up through the first embodiment in this paragraph, wherein thehydrocarbon stream comprises naphtha boiling range hydrocarbons. Anembodiment of the invention is one, any or all of prior embodiments inthis paragraph up through the first embodiment in this paragraph whereinthe hydrocarbon stream comprises straight run naphtha from crude oil ornatural gas condensate sources. An embodiment of the invention is one,any or all of prior embodiments in this paragraph up through the firstembodiment in this paragraph, wherein the clinoptilolite adsorbent orthe barium exchanged zeolite adsorbent has exchangeable cations selectedfrom ions of Group 1A, Group 2A, Group 3A, Group 3B, the lanthanideseries and mixtures of these. An embodiment of the invention is one, anyor all of prior embodiments in this paragraph up through the firstembodiment in this paragraph, wherein the clinoptilolite adsorbent orthe barium exchanged zeolite adsorbent is selected from naturalclinoptilolite, synthetic clinoptilolite, sodium-exchangedclinoptilolite, potassium-exchanged clinoptilolite, lithium-exchangedclinoptilolite, calcium-exchanged clinoptilolite, magnesium-exchangedclinoptilolite, barium-exchanged clinoptilolite, and mixtures thereof.An embodiment of the invention is one, any or all of prior embodimentsin this paragraph up through the first embodiment in this paragraph,wherein the clinoptilolite adsorbent or the barium exchanged zeoliteadsorbent is sodium-exchanged clinoptilolite or barium-exchangedclinoptilolite. An embodiment of the invention is one, any or all ofprior embodiments in this paragraph up through the first embodiment inthis paragraph, further comprising contacting the hydrocarbon streamhaving a reduced CS2 content with a zeolite adsorbent or a promotedalumina adsorbent to remove at least one impurity selected from thegroup consisting of oxygenates and other sulfur compounds. An embodimentof the invention is one, any or all of prior embodiments in thisparagraph up through first embodiment in this paragraph, wherein theclinoptilolite adsorbent or the barium exchanged zeolite adsorbent isused in a temperature swing adsorption system where the adsorptiontemperature is between 60-150° F. and the regeneration temperature isbetween 300 and 550° F. An embodiment of the invention is one, any orall of prior embodiments in this paragraph up through the firstembodiment in this paragraph, further comprising regenerating theclinoptilolite adsorbent or the barium exchanged zeolite adsorbent witha portion of the hydrocarbon stream having a reduced CS2 content, ahydrogen stream or a mixture of said hydrocarbon stream having a reducedCS₂ content and hydrogen. An embodiment of the invention is one, any orall of prior embodiments in this paragraph up through the firstembodiment in this paragraph, where a regeneration effluent stream isdirected to a hydrotreater, a hydrocracker or another hydrogenconsumption process. An embodiment of the invention is one, any or allof prior embodiments in this paragraph up through the first embodimentin this paragraph wherein the clinoptilolite adsorbent or the bariumexchanged zeolite adsorbent is regenerated with a hydrocarbon streamthat was first sent through a hydrotreater. An embodiment of theinvention is one, any or all of prior embodiments in this paragraph upthrough the first embodiment in this paragraph where the regenerantstream is a hydrotreated naphtha stream available at a temperature of15.5-287.8° C. (60-550° F.). An embodiment of the invention is one, anyor all of prior embodiments in this paragraph up through the firstembodiment in this paragraph wherein the regenerant stream is at atemperature from about 148.9-287.8° C. (300-550° F.). An embodiment ofthe invention is one, any or all of prior embodiments in this paragraphup through the first embodiment in this paragraph where the regenerantstream is a light hydrotreated naphtha from a naphtha splitter overheadat a temperature of 15.5-287.8° C. (60-550° F.). An embodiment of theinvention is one, any or all of prior embodiments in this paragraph upthrough the first embodiment in this paragraph where the regenerantstream is alight hydrotreated naphtha from a naphtha splitter overheadat a temperature of 93.3-204.4═ C. (200-400° F.). An embodiment of theinvention is one, any or all of prior embodiments in this paragraph upthrough the first embodiment in this paragraph, where the regenerationeffluent is directed to a hydrotreater at a temperature of 15.5-287.8°C. (60-550° F.) An embodiment of the invention is one, any or all ofprior embodiments in this paragraph up through the first embodiment inthis paragraph wherein the regeneration effluent is at a temperature of148.9-287.8° C. (300-550° F.).

A second embodiment of the invention is a process for removing CS₂ fromhydrocarbon streams comprising contacting a hydrocarbon stream with azeolite adsorbent comprising a chabazite zeolite, an erionite zeolite, aclinoptilolite zeolite or mixtures thereof to produce a hydrocarbonstream having a reduced CS₂ content. An embodiment of the invention isone, any or all of prior embodiments in this paragraph up through thefirst embodiment in this paragraph, wherein the adsorbent is ionexchanged with barium. An embodiment of the invention is one, any or allof prior embodiments in this paragraph up through the first embodimentin this paragraph, wherein the zeolite adsorbent is regenerated with aregeneration stream comprising a portion of said hydrocarbon streamhaving a reduced CS₂ content, a hydrogen stream or a mixture of saidhydrocarbon stream having a reduced CS₂ content and hydrogen.

Without further elaboration, it is believed that using the precedingdescription that one skilled in the art can utilize the presentinvention to its fullest extent and easily ascertain the essentialcharacteristics of this invention, without departing from the spirit andscope thereof, to make various changes and modifications of theinvention and to adapt it to various usages and conditions. Thepreceding preferred specific embodiments are, therefore, to be construedas merely illustrative, and not limiting the remainder of the disclosurein any way whatsoever, and that it is intended to cover variousmodifications and equivalent arrangements included within the scope ofthe appended claims.

In the foregoing, all temperatures are set forth in degrees Celsius and,all parts and percentages are by weight, unless otherwise indicated.

1. A process for removing CS₂ from hydrocarbon streams comprisingcontacting a hydrocarbon stream with a clinoptilolite adsorbent or abarium exchanged zeolite adsorbent to produce a hydrocarbon streamhaving a reduced CS2 content.
 2. The process of claim 1, wherein thehydrocarbon stream comprises naphtha boiling range hydrocarbons.
 3. Theprocess of claim 1 wherein the hydrocarbon stream comprises straight runnaphtha from crude oil or natural gas condensate sources.
 4. The processof claim 1, wherein said clinoptilolite adsorbent or barium exchangedzeolite adsorbent has exchangeable cations selected from ions of Group1A, Group 2A, Group 3A, Group 3B, the lanthanide series and mixtures ofthese.
 5. The process of claim 1, wherein said clinoptilolite adsorbentor barium exchanged zeolite adsorbent is selected from naturalclinoptilolite, synthetic clinoptilolite, sodium-exchangedclinoptilolite, potassium-exchanged clinoptilolite, lithium-exchangedclinoptilolite, calcium-exchanged clinoptilolite, magnesium-exchangedclinoptilolite, barium-exchanged clinoptilolite, and mixtures thereof.6. The process of claim 1, wherein said clinoptilolite adsorbent orbarium exchanged zeolite adsorbent is sodium-exchanged clinoptilolite orbarium-exchanged clinoptilolite.
 7. The process of claim 1, furthercomprising contacting said hydrocarbon stream having a reduced CS₂content with a zeolite adsorbent or a promoted alumina adsorbent toremove at least one impurity selected from the group consisting ofoxygenates and other sulfur compounds.
 8. The process of claim 1,wherein said clinoptilolite adsorbent or barium exchanged zeoliteadsorbent is used in a temperature swing adsorption system where theadsorption temperature is between 60° and 150° F. and the regenerationtemperature is between 300° and 550° F.
 9. The process of claim 1,further comprising regenerating said clinoptilolite adsorbent or bariumexchanged zeolite adsorbent with a regeneration stream comprising aportion of said hydrocarbon stream having a reduced CS₂ content, ahydrogen stream or a mixture of said hydrocarbon stream having a reducedCS₂content and hydrogen.
 10. The process of claim 9 where a regenerationeffluent stream is directed to a hydrotreater, or a hydrocracker orother hydrogen consumption process.
 11. The process of claim 1 whereinsaid clinoptilolite adsorbent or barium exchanged zeolite adsorbent isregenerated with a hydrocarbon stream that was first sent through ahydrotreater.
 12. The process of claim 11 where the regenerant stream isa hydrotreated naphtha stream available at a temperature of 15.5° to287.8° C. (60° to 550° F.).
 13. The process of claim 12 wherein theregenerant stream is at a temperature from about 148.9° to 287.8° C.(300° to 550° F.).
 14. The process of claim 11 where the regenerantstream is a light hydrotreated naphtha from a naphtha splitter overheadat a temperature of 15.5° to 287.8° C. (60° to 550° F.).
 15. The processof claim 11 where the regenerant stream is a light hydrotreated naphthafrom a naphtha splitter overhead at a temperature of 93.3° to 204.4° C.(200° to 400° F.).
 16. The process of claim 11, where the regenerationeffluent is directed to a hydrotreater at a temperature of 15.5° to287.8° C. (60° to 550° F.).
 17. The process of claim 16 wherein theregeneration effluent is at a temperature of 148.9° to 287.8° C. (300°to 550° F.).
 18. A process for removing CS₂ from hydrocarbon streamscomprising contacting a hydrocarbon stream with a zeolite adsorbentcomprising a chabazite zeolite, an erionite zeolite, a clinoptilolitezeolite or mixtures thereof to produce a hydrocarbon stream having areduced CS₂ content.
 19. The process of claim 18 wherein said zeoliteadsorbent is ion exchanged with barium.
 20. The process of claim 18,further comprising regenerating said zeolite adsorbent with aregeneration stream comprising a portion of said hydrocarbon streamhaving a reduced CS₂ content, a hydrogen stream or a mixture of saidhydrocarbon stream having a reduced CS₂ content and hydrogen.